Wellbore fluid comprising a base fluid and a particulate bridging agent

ABSTRACT

A wellbore fluid comprising a base fluid and a particulate bridging agent comprised of a sparingly water-soluble material selected from the group consisting of melamine (2,4,5-triamino-1,3,5-triazine), lithium carbonate, lithium phosphate (Li 3 PO 4 ), and magnesium sulfite.

The present invention relates to wellbore fluids utilized in theconstruction, repair or treatment of a wellbore and to the removal offilter cake deposited by the wellbore fluids on or in rock formationspenetrated by the wellbore.

Wellbore fluids include drilling fluids, lost circulation fluids,completion fluids (such as perforating pills and under-reaming fluids),and servicing fluids (such as workover fluids, milling fluids,fracturing fluids, solvents, aqueous fluids containing non-acidicdissolving agents, and fluids containing particulate diverting agents).

Drilling fluids are utilized when drilling a wellbore through a porousand permeable rock formation, for example, a hydrocarbon-bearing rockformation. It is highly desirable that the drilling fluid minimizesdamage to the permeability of the rock formation. For example, damage tothe permeability of a hydrocarbon-bearing rock formation may result inproduction losses or a reduced ability of the formation to acceptinjected fluids (for example, water or treatment fluids).

Completion fluids are utilised during operations that take place in theso-called completion phase of a wellbore (after drilling of the wellboreand before commencement of production of fluids from a rock formationinto the wellbore or injection of fluids from the wellbore into a rockformation). Again, it is highly desirable that completion fluidsminimize damage to the permeability of rock formations.

Servicing fluids may be utilized intermittently during the life of awellbore, for example, when conducting work-over, stimulation orremedial operations in a rock formation penetrated by the wellbore. Forexample, where the servicing fluid is a fracturing fluid, it is highlydesirable that leak-off of fluid from the fractures that are induced inthe walls of the wellbore is minimized.

Drilling, completion or servicing fluids usually comprise a particulatesolid bridging agent of a particle size that is large enough forbridging the pore throats of a porous and permeable rock formation and afiltration control additive (often termed a “fluid loss controladditive”). The drilling, completion or servicing fluids deposit a layerof particles known as a “filter cake” on the walls of the wellbores.Where the wellbore penetrates a porous and permeable rock formation,this low-permeability filter cake prevents large amounts of fluids(“filtrate”) from being lost from the drilling, completion or servicingfluid into the rock formation and also prevents solids from entering thepores of the formation. Fluid that is lost from a drilling, completionor servicing fluid into a porous and permeable rock formation is termed“filtrate”. The filter cake is comprised of the particulate bridgingagent and the fluid loss control agent and will also include othersolids that are present in the wellbore fluid and are capable ofdepositing onto the walls of the wellbore. After the drilling,completion or servicing of the wellbore, it is advantageous that as muchas possible of the filter cake is removed before commencing productionof fluids from a porous and permeable rock formation into the wellboreor before fluid is injected into a porous and permeable rock formationfrom the wellbore. However, it is often difficult to access and removesubstantial amounts of the filter cake.

In the event that a large volume of wellbore fluid is being lost throughhigh conductivity conduits in the walls of a wellbore into a porous andpermeable rock formation, a lost circulation fluid comprising a LostCirculation Material (LCM) suspended in a base fluid is pumped into thewellbore. The high conductivity conduits are typically fissures,fractures or vugs in the walls of the wellbore (where a vug is a cavity,void or large pore in a rock formation). Lost circulation fluidsfrequently comprise coarser particulate solids (LCM) man the particulatebridging agents of drilling, servicing or completion fluids in order tobridge and seal the high conductivity conduits into which the wellborefluid is being lost. Thus, a relatively low permeability plug comprisingthe particulate LCM and optionally other solids is deposited from thelost circulation fluid in the high conductivity conduits. Theseparticulate plugs can be difficult to remove from the high conductivityconduits when it is desired to commence production of fluids from a rockformation into a production wellbore or injection of fluids into a rockformation from an injection wellbore.

Conventionally, filter cakes are removed from wellbore walls bycontacting the filter cakes with one or more clean-up fluids. One commonbridging agent for bridging the pore throats of a porous formation andfor plugging any high conductivity conduits (e.g. fissures) therein ispowdered calcium carbonate. The filter cake may be removed by using aclean-up fluid comprising enzymes and oxidizers to degrade the fluidloss control additive prior to contacting the filter cake with astrongly acidic clean-up solution for a sufficient period of time todissolve the particulate calcium carbonate bridging agent. However,despite current anti-corrosion steps, the strongly acidic solution oftencorrodes metallic surfaces and completion equipment such as sand controlscreens causing early failure of such equipment. The acidic clean-upsolution may also be incompatible with the producing formation and maycause formation damage. In addition, inefficient dissolution of filtercake occurs when an acidic clean-up solution reacts rapidly with aportion of the filter cake, opening up fluid communication between theclean-up fluid in the wellbore and the permeable formation, whereuponthe clean-up fluid enters the formation without contacting the remainingfilter cake. Another problem arises when an expandable sandscreen isplaced in an open hole wellbore in the interval of the wellbore adjacentto a hydrocarbon-bearing formation. After placement of the sandscreen,it is expanded to fit the diameter of the wellbore thereby providingexcellent support to the wellbore and exclusion of sand production.Unfortunately, this results in the filter cake becoming trapped betweenthe expanded sandscreen and the formation so that it is very difficultto access the filter cake with a clean-up solution. Under suchcircumstances it would be advantageous if the filter cake were solublein less-corrosive and less-damaging fluids, for example, naturallyoccurring wellbore fluids. In this way untreated or trapped filter cakeshould ultimately be reached by and become dissolved in the fluids.

Where the filter cake is deposited on and/or in the walls of ahydrocarbon production wellbore, the hydrocarbon-bearing formation willgenerally produce a significant proportion of water. Where the filtercake is deposited on and/or in the walls of a water injection well or awater producing well, the filter cake will again be exposed to largevolumes of water over a long period of time. Where the filter cake isdeposited on and/or in the walls of a geothermal wellbore, the filtercake will be exposed to hot water and steam. Accordingly, particulatesolid bridging agents formed of a water-soluble salt (for example,alkali metal halides) or a sparingly water-soluble salt (for example,magnesium borate and magnesium salts of carboxylic acids) have beenutilized or proposed in drilling or servicing fluids. Thus, filter cakescontaining the water-soluble or sparingly water-soluble bridging agenthave been removed by contacting the filter cake with an aqueous saltsolution which is undersaturated with respect to the water-soluble orsparingly water-soluble salt. These water-soluble or sparinglywater-soluble bridging agents may be employed in either an oil-basedtreatment fluid or in an aqueous based treatment fluid provided that theaqueous base fluid is saturated with respect to the water-soluble orsparingly water-soluble salt. However, there remains a need for furtherwellbore fluids where the bridging agent is comprised of a sparinglywater-soluble material.

Accordingly, the present invention relates to a wellbore fluidcomprising a base fluid and a particulate bridging agent comprised of asparingly water-soluble material selected from the group consisting ofmelamine (2,4,5-triamino-1,3,5-triazine), lithium carbonate, lithiumphosphate (Li₃PO₄), and magnesium sulfite, preferably, melamine andlithium carbonate.

The term “wellbore fluid” as used herein encompasses drilling fluids,lost circulation fluids, completion fluids such as perforating pills andunder-reaming fluids, and servicing fluids such as kill fluids, workoverfluids, milling fluids, fracturing fluids, solvents, non-acidic aqueousdissolving agents, and fluids containing particulate diverting agents.

The wellbore fluid of the present invention is suitable for use in avariety of wellbores including oil and/or gas producing wellbores, wateror gas injection wellbores, water producing wellbores and geothermalwellbores.

The sparingly water-soluble materials that have been selected for use asthe particulate bridging agent have a solubility in water at atemperature of 25° C. of less than 7% by weight, preferably less than 2%by weight. In addition, these materials have a solubility in water at atemperature of 80° C. of less than 7% by weight, preferably less than3.5% by weight.

Optionally, a fluid loss control additive is included in the wellborefluid of the present invention.

The present invention also provides a method of forming a removablefilter cake on the walls of a wellbore that penetrates a porous andpermeable rock formation comprising the steps of:

-   (a) placing a wellbore fluid in the wellbore wherein the wellbore    fluid comprises a base fluid and a particulate bridging agent    comprised of a sparingly water-soluble material selected from the    group consisting of melamine, lithium carbonate, lithium phosphate    (Li₃PO₄), and magnesium sulfite, preferably, melamine and lithium    carbonate; and-   (b) permitting the particulate bridging agent to deposit from the    wellbore fluid onto and/or into the walls of the wellbore thereby    forming the removable filter cake, whereby fluid loss to the    formation through the filter cake is reduced.

Suitably, the particulate bridging agent may bridge the pore throats ofthe rock formations penetrated by the wellbore and/or may enter anycracks, fissures, fractures, or vugs in the wellbore wall.

Optionally, a fluid loss control additive is included in the wellborefluid.

By “removable” is meant that the filter cake may be removed withoutpumping a specialised clean-up fluid into the wellbore. In other words,the filter cake may be self-removing.

The filter cake is permitted to build up on the walls of the wellboreowing to the pressure of the wellbore fluid in the wellbore beingmaintained at above the pore-pressure of the porous and permeableformation that is penetrated by the wellbore. Preferably, thedifferential pressure between the pressure of the wellbore fluid in thewellbore and the pore-pressure is at least 200 psi.

Where the wellbore is a hydrocarbon production wellbore, the bridgingagent may be removed by putting the well into production owing to thewater that is co-produced with the hydrocarbon dissolving the sparinglywater-soluble material. Where the wellbore is a water production well ora geothermal well, the bridging agent may be removed by putting the wellinto production owing to the sparingly water-soluble material dissolvingin the produced water. Where the wellbore is a water injection well, thefilter cake may be removed by commencing water injection owing to theinjected water dissolving the sparingly water-soluble material. Thus,both the produced water and injected water are undersaturated withrespect to the sparingly water-soluble material. The bridging agent canbe eventually completely solubilised in water or alternativelysolubilised to the extent that the particles are sufficiently reduced insize to permit their removal from the formation with the produced orinjected water. The time required to solubilise the particles depends ona number of factors including, the temperature in the wellbore, the sizeand shape of the bridging agent particles, and the amount of water matthe filter cake is exposed to. The filter cake is expected to subsistfor less than 200 hours when a production well is put into production orwhen water is injected into an injection well.

Optionally, if rapid dissolution is required, a clean-up fluid may bepumped into the wellbore. The clean-up fluid may be an aqueous fluidthat is under-saturated with respect to the bridging agent. Preferably,the clean-up fluid is an aqueous solution of an acid, preferably, anaqueous solution of a weak acid or a precursor of a weak acid.Preferably, the weak acid is selected from the group consisting offormic acid, citric acid, acetic acid, lactic acid, glycolic acid,succinic acid, and acidic sequestrants such as those based uponpartially neutralised ethylenediaminetetracetic acid (EDTA). Preferably,the precursor of the weak acid is selected from materials that arecapable of hydrolysing to produce weak acids such as the polyglycolic orpolylactic homopolyesters and orthoesters such as orthoformate esters.Preferably, the weak acid or acid precursor is present in the clean-upfluid in an amount of between 1% and 20% by weight An advantage of usingan aqueous solution of a weak acid or an aqueous solution of a precursorof a weak acid is that the clean-up fluid is less corrosive to metalsurfaces and equipment than the strong acids that are used to dissolveconventional inorganic bridging agents such as calcium carbonate. Afurther advantage of the sparingly water-soluble materials employed inthe present invention is that even partial reaction with an acid formsproducts having a higher solubility in water. Thus, lithium carbonate isconverted to lithium bicarbonate, lithium phosphate (Li₃PO₄) isconverted to lithium hydrogen phosphates, and magnesium sulfite isconverted to magnesium bisulfite upon partial reaction with an acid. Allof these products are of much higher solubility than their sparinglywater-soluble precursors. In addition, the amine groups that are presentin melamine will protonate under mildly acidic conditions, greatlyincreasing the water-solubility of the bridging agent.

Where the sparingly water-soluble particulate bridging agent iscomprised of magnesium sulfite, the clean-up fluid may comprise anaqueous solution of an oxidizing agent that is capable of convertingmagnesium sulfite to water-soluble magnesium sulfate. Thus, magnesiumsulfate has a much higher solubility in water man magnesium sulfite.Suitable oxidizing agents include hydrogen peroxide, persulfate salts,and per-acids such as peracetic acid. Preferably, the oxidizing agent ispresent in the clean-up fluid in an amount of 1 to 20% by weight.Optionally, the clean-up fluid also-comprises a weak acid or a precursorof a weak acid.

Where the sparingly water-soluble particulate bridging agent iscomprised of melamine, it is envisaged that the removable filter cakemay be removed from the walls of a wellbore by placing an aqueous washfluid downhole and leaving the aqueous wash fluid to soak in theinterval of the wellbore where it is desired to remove the filter cake.The soak time should be sufficient for the aqueous wash fluid to heat upto a temperature of at least 60° C., preferably at least 75° C., forexample, at least 90° C. Because the solubility of melamine increasesrelatively rapidly with increasing temperature, the particulate bridgingagent is either completely dissolved in the aqueous wash fluid or issolubilised to the extent that the particles are sufficiently reduced msize to permit their removal from the formation. The aqueous wash fluidis heated to the desired temperature owing to transfer of geothermalheat from the formation. Typically, it may take at least several hours,for example, about 1 day for the aqueous wash fluid to be heated to thedesired temperature. In general, the operator will be able to determinemat a sufficient period of time has elapsed when the fluid loss ratefrom the wellbore to the formation increases.

The rate of dissolution of the bridging agents in water is also enhancedby the presence of carbon dioxide. Accordingly, the high partialpressures of carbon dioxide that are often present in fluids producedfrom hydrocarbon-bearing formations can be expected to acceleratedissolution of the bridging agent.

Optionally, a clean-up fluid is placed downhole and left to soak acrossthe interval of the wellbore where it is desired to remove the filtercake for a sufficient period of time to either completely dissolve thebridging agent or to solubilise the bridging agent to the extent thatthe particles are sufficiently reduced in size to permit their removalfrom the formation. The clean-up fluid may contain enzymes or oxidisingagents to degrade the fluid-loss control and viscosifying polymers thataccumulate in the filter-cake, and may contain acids or acid precursorsto speed the dissolution of the bridging solids. Preferably, theoptional clean-up solution is left to soak for about 2 to 24 hours. Ingeneral, the operator will be able to determine that a sufficient periodof time has elapsed when the fluid loss rate from the wellbore to theformation increases. Thereafter, a wash fluid (for example, an aqueousfluid such as water or seawater or a dilute brine) may be pumped at ahigh rate into the wellbore in order to create turbulent cleaningconditions thereby removing the remaining filter cake from the walls ofthe wellbore. Alternatively, the remaining filter cake may be removed byproducing water from the formation or by injecting water into theformation.

Preferably, the wellbore fluid is selected from (a) a drilling fluid;(b) a fluid used to control lost circulation (termed “loss circulationfluid”); (c) a completion fluid used during completion operations; and(d) a well-servicing fluid used when conducting work-over, stimulationor remediation operations.

Thus, in a preferred embodiment of the present invention there isprovided a method of drilling a wellbore through a porous and permeablerock formation using a drilling fluid comprising a base fluid, a fluidloss control additive, and a particulate bridging agent comprised of asparingly water-soluble material selected from the group consisting ofmelamine, lithium carbonate, lithium phosphate (Li₃PO₄), and magnesiumsulfite wherein the pressure of the drilling fluid in the wellbore ismaintained at above the pressure in the porous and permeable rockformation such that a filter cake deposits on and/or in the walls of thewellbore and reduces fluid loss from the drilling fluid to the rockformation.

By being deposited “in the walls of the wellbore” is meant that filtercake may be deposited in any cracks, fractures, fissures or vugs thatare present in the walls of the wellbore.

Suitably, the wellbore that is drilled using this preferred embodimentof the present invention is a hydrocarbon production wellbore (an oil orgas well), an injection wellbore (for example, a water or gas injectionwell), a water-producing wellbore or a geothermal wellbore.

In another preferred embodiment of the present invention there isprovided a method of controlling loss of fluid from a wellbore into aporous and permeable rock formation through a high conductivity conduitthat extends from the wellbore into the rock formation comprising thesteps of:

-   (a) placing a lost circulation fluid in the wellbore wherein the    lost circulation fluid comprises a slurry of particulate lost    circulation material (LCM) in a base fluid wherein the LCM is    suspended in the base fluid in an amount of at least 5 pounds per    barrel, preferably at least 10 pounds per barrel, more preferably at    least 20 pounds per barrel, and most preferably at least 30 pounds    per barrel, and is comprised of a sparingly water-soluble material    selected from the group consisting of melamine, lithium carbonate,    lithium phosphate (Li₃PO₄), and magnesium sulfite; and-   (b) permitting the LCM to accumulate in, or at the entrance of, the    high conductivity conduit thereby forming a removable    low-permeability plug that bridges the conduit whereby fluid loss to    the formation through the conduit is reduced.

By “removable” is meant that the plug may be removed without theassistance of a specifically designed clean-up fluid.

The slurry is pumped into the interval of the wellbore where a highconductivity conduit (for example a fissure) is present in the wall ofthe wellbore and through which fluid is being lost into the porous andpermeable rock formation, for example, a hydrocarbon-bearing rockformation. Filtration of the slurry results in deposition of theparticulate LCM in the high conductivity conduit such that the conduitbecomes filled with a solid pack of LCM particles. Optionally, a fluidloss control agent may be present in the slurry thereby assisting insealing the high conductivity conduit. Preferably the sealing of theconduit is made more complete when a subsequent wellbore fluid such asdrilling fluid, in particular, a low fluid loss drilling fluid, forms animpermeable filter cake upon the plug of particulate LCM.

In yet another preferred embodiment of the present invention there isprovided a method of controlling loss of fluid from a completion fluidinto a porous and permeable rock formation penetrated by a wellbore by:

-   (a) placing a completion fluid in the wellbore wherein the    completion fluid comprises a base fluid, a fluid loss control    additive, and a particulate bridging agent comprised of a sparingly    water-soluble material selected from the group consisting of    melamine, lithium carbonate, lithium phosphate, and magnesium    sulfite; and-   (b) maintaining the pressure of the completion fluid in the wellbore    at above the pore-pressure of the rock formation such that a filter    cake deposits on or in the walls of the wellbore.

Suitably, the completion fluid (and also the drilling fluid referred toabove) additionally contains a polymeric viscosifier(s) such as xanthangum, hydroxyethylcellulose, welan gum (for example, Biozan™; ex Kelco)or diutan gum (for example, Geovis XT™; ex Kelco). The completion fluidthat is placed in the wellbore may fill the entire wellbore.Alternatively, the completion fluid may be employed as a pill ofsufficient volume to fill the interval of the wellbore that is to be“completed” with the remainder of the wellbore being filled with asecond fluid having an appropriate density for well control purposes.Thus, the density of the second fluid is chosen such that fluid does notflow from a rock formation into the wellbore. It is envisaged that thesecond fluid may be a brine that is substantially free of suspendedsolids.

It is also envisaged that the wellbore may be a cased wellbore that isperforated in an interval of the wellbore that lies across a porous andpermeable rock formation, for example, a hydrocarbon-bearing rockformation. Accordingly, the filter cake will deposit from the completionfluid in the perforation tunnels formed in the cased wellbore therebyreducing fluid loss from the completion fluid to the formation.

In yet a further preferred embodiment of the present invention, there isprovided a method of controlling loss of fluid from a workover fluid toan interval of a wellbore that lies across a porous and permeable rockformation wherein the method comprises the steps of:

-   (a) pumping a sufficient volume of a first workover fluid to fill    the interval of the wellbore that lies across the porous and    permeable rock formation wherein the first workover fluid comprises    a base fluid, a fluid loss control additive, and a particulate    bridging agent comprised of a sparingly water-soluble material    selected from the group consisting of melamine, lithium carbonate,    lithium phosphate, and magnesium sulfite such that a removable    filter cake deposits from the first workover fluid in said interval    of the wellbore onto the walls of the wellbore and into any cracks,    fractures or fissures therein;-   (b) pumping a second workover fluid into the wellbore wherein the    second workover fluid is of sufficient density to at least    counterbalance the pressure of the porous and permeable rock    formation;-   and wherein the filter cake deposited in step (a) reduces fluid loss    from the workover fluids to the porous and permeable rock formation.

The second workover fluid may be of the same composition as the firstworkover fluid or may be of a different composition, for example asolids free brine or oil. In the case of aqueous workover fluids, it ispreferred that the second workover fluid is substantially saturated withrespect to the sparingly water-soluble material that comprises theparticulate bridging agent of the first workover fluid. The firstworkover fluid is used to seal the formation to prevent fluid lossesfrom the second workover fluid while the second workover fluid is usedto perform functions such as maintaining well control (hydrostatichead), circulating debris such as “milled out” downhole equipment out ofthe wellbore (for example, “milled out” packers or screens), providing alow viscosity fluid to allow the easy running of tools in and out of thewellbore and acting as a “re-completion” fluid.

Where the wellbore is a cased wellbore that is perforated in theinterval of the wellbore across a porous and permeable rock formation,the filter cake will deposit from the first workover fluid in theperforation tunnels in the casing of the wellbore thereby reducing fluidloss from the second workover fluid to the formation.

Wells that require a “workover” are often depleted hydrocarbonproduction wells where the hydrocarbon-bearing rock formation has a lowpore pressure. Accordingly, the hydrostatic head of the second workoverfluid in the interval of the wellbore across the hydrocarbon-bearingrock formation may be greatly in excess of the pore pressure in thedepleted hydrocarbon-bearing rock formation even when the secondworkover fluid is a simple low-density fluid such as water (for example,seawater), or an oil. Accordingly, the ability to control fluid loss bythe method described above is more important at high differentialpressures (where the pressure of the second workover fluid in thewellbore is significantly higher than the pore pressure of the rockformation).

Fracturing fluids generally comprise a proppant (for example, sandparticles or ceramic beads) suspended in an aqueous base fluid that isnormally viscosified by a polymer or a viscoelastic surfactant such thatthe proppant that is used to prop open the fractures is efficientlytransported into the fractures that are created when the fracturingfluid is pumped at high pressure into a porous and permeable rockformation. However, if the fracturing fluid leaks off too quickly intothe formation the high pressure dissipates and the fractures cease togrow. Leak-off control is normally achieved by dispersing groundparticles such as silica flour in the fracturing fluid to block/bridgethe exposed pores in the fracture that are accepting the “leak-off”.Unfortunately, materials like silica may cause at least some permanentplugging of the pores of the formation.

Accordingly, in yet another preferred embodiment of the presentinvention there is provided a method of fracturing a porous andpermeable rock formation comprising:

-   injecting a fracturing fluid into an interval of a wellbore across    the rock formation that is to be fractured wherein the fracturing    fluid comprises a base fluid, proppant, a viscosifer, and a    particulate leak-off control agent comprised of a sparingly    water-soluble material selected from the group consisting of    melamine, lithium carbonate, lithium phosphate, and magnesium    sulfite; and-   maintaining the pressure of the fracturing fluid in the interval of    the wellbore across the rock formation at above the fracture    pressure of the formation whereby proppant enters and props open the    fractures that are formed in the wellbore wall and the particulate    leak-off control agent seals exposed pore throats on the walls of    the fracture.

An advantage of this preferred embodiment of the present invention isthat the pressure of the fracturing fluid in the growing fracture ismaintained for as long as possible at above the fracturing pressure ofthe rock formation by reducing leak-off of fluid to the formation andhence reducing pressure dissipation to the formation. Where thefractures are formed in a hydrocarbon-bearing rock formation penetratedby a production wellbore, the particulate bridging material willdissolve in co-produced water upon returning the wellbore to productionthereby improving the flow of fluid from the hydrocarbon-bearingformation. Where the fractures are formed in a porous and permeable rockformation penetrated by a water injection well, the particulate bridgingmaterial will dissolve in water that is injected into the rockformation, thereby improving the flow of fluid from the injection wellinto the formation.

In another embodiment of the present invention, there is provided amethod of diverting non-acidic treatment fluids away from highpermeability rock formations or high conductivity conduits and intolower permeability and/or partially plugged rock formations or lowerconductivity conduits using a treatment fluid comprising a non-acidicfluid and a particulate bridging agent comprised of a sparinglywater-soluble material selected from the group consisting of melamine,lithium carbonate, lithium phosphate (Li₃PO₄), and magnesium sulfite.For example, where the non-acidic fluid is an aromatic solvent, thetreatment fluid may be used to dissolve wax and/or asphaltene depositsthat plug flow channels in oil wells (and hence reduce oil production).The method comprises pumping a suspension comprising the particulatebridging agent suspended in an aromatic solvent into a hydrocarbonproduction wellbore such that a filter cake forms on or in a highpermeability rock formation or the particulate bridging agent enters andseals high conductivity conduits (or flow channels) in the walls of thewellbore thereby limiting the loss of aromatic solvent from thewellbore. Accordingly, the aromatic solvent is diverted towards lowconductivity conduits (or flow channels) that may be damaged byasphaltene and/or wax deposits, thereby improving the dissolution of thedeposits by the aromatic solvent.

Preferred features of the wellbore fluid of the present invention willnow be described below.

The base fluid of the wellbore fluid may be water, an oil (for example,a mineral oil), a solvent (for example, an aromatic solvent), or amixture thereof (for example, a water-in-oil emulsion). Generally, thebase fluid is present in the wellbore fluid in an amount in the range offrom about 30 to 99% by weight of the fluid, preferably, about 70 to 97%by weight.

Where the base fluid is water, it is preferred that the base fluid is anaqueous solution of a density increasing water-soluble salt. The densityincreasing water-soluble salt may be selected from the group consistingof alkali metal halides (for example, sodium chloride, sodium bromide,potassium chloride and potassium bromide) alkali metal carboxylates (forexample, sodium formate, potassium formate, caesium formate, sodiumacetate, potassium acetate or caesium acetate), sodium carbonate,potassium carbonate, alkaline earth metal halides (for example, calciumchloride and calcium bromide), and zinc halide salts.

Alternatively, density control may be provided to the water-basedwellbore fluid using insoluble weighting agents. Suitable weightingagents include suspended mineral particles such as ground barites, ironoxides, (for example, haematite), ilmenite, calcite, magnesite (MgCO₃),dolomite, olivine, siderite, hausmannite or suspended metal particles.

Where the base fluid is an oil, it is preferred that the oil is selectedfrom the group consisting of mineral oils, synthetic oils, esters,kerosene, and diesel.

The base fluid may also be a water-in-oil emulsion comprising dropletsof an aqueous phase dispersed in a continuous oil phase. Suitably, theaqueous phase of the emulsion comprises an aqueous solution of a densityincreasing water-soluble salt thereby increasing the density of thewellbore fluid. Suitable density-increasing water-soluble salts arelisted above. Preferably, the concentration of salt in the disperseddroplets of aqueous phase is adjusted to provide a Water Activitysimilar to that of the underground formation being contacted by thewellbore fluid. The continuous oil phase may be any oil in which anaqueous solution of salts can be emulsified. Suitable oils are listedabove. An advantage of a water-in-oil emulsion is that this enhancesboth filtration control (owing to the emulsion droplets blocking theflow of fluid through the filter cake) and the viscous properties of thefluid. The term oil-based wellbore fluid as used herein encompasseswellbore fluids where the base fluid is a water-in-oil emulsion.

Density control may also be provided to the oil-based wellbore fluidusing weighting agents. Suitable weighting agents areas listed above foraqueous-based wellbore fluids.

Where the base fluid is water, the particulate bridging agent comprisedof a sparingly water-soluble material selected from the group consistingof melamine, lithium carbonate, lithium phosphate, and magnesium sulfite(hereinafter “sparingly water-soluble particulate bridging agent”) isdosed into the wellbore fluid at a concentration that is significantlyhigher than its solubility in water at the temperature encountereddownhole thereby ensuring at least a portion of the bridging solidsremain suspended in the wellbore fluid. Alternatively, the sparinglywater-soluble particulate bridging agent may be protected with ahydrophobic coating that is capable of dissolving in a produced liquidhydrocarbon, for example, a produced oil or produced gas condensate.However, such coated particulate bridging agents should not be employedwhen drilling or completing water injection wells or gas wells that are,free of gas condensate.

Generally the sparingly water-soluble particulate bridging agent ispresent in the wellbore fluid in an amount sufficient to create anefficient filter cake that provides the desired level of fluid losscontrol. Typically, the sparingly water-soluble particulate bridgingagent is present in the wellbore fluid in an amount in the range of 1 to70% by weight, preferably 2 to 50% by weight, more preferably, 3 to 30%by weight, in particular 3 to 15% by weight. High doses are preferredfor lost circulation fluids, for example 10 to 60% by weight.

The desired particle size distribution of the sparingly water-solubleparticulate bridging material is determined by the size of any fracturesand the like into which the wellbore fluid is being lost or by the porethroat size of the formation that is to be drilled or treated.Typically, for use as a Lost Circulation material the sparinglywater-soluble particulate bridging agent has a particle sizedistribution in the range of from about 50 microns to about 10 mm,preferably 50 microns to about 2 mm. For use as a bridging solid in adrilling, servicing or completion fluid the sparingly water-solubleparticulate bridging agent has a particle size distribution in the rangeof from about 0.1 micron to 600 microns, preferably 0.1 to 200 microns,and more preferably 0.1 to 100 microns. Preferably, the sparinglywater-soluble particulate bridging material has a broad polydispersesize distribution. The materials (lithium carbonate, lithium phosphate,magnesium sulfite and melamine) are available as crystalline materialsof the desired size or as crystals or granules that can be ground to thedesired size. The sparingly water-soluble particulate bridging materialmay be in the form of substantially spherical particles or may be of anirregular shape.

More than one sparingly water-soluble particulate bridging agent may beemployed in the wellbore fluid.

The wellbore fluids may additionally comprise one or more of thefollowing materials: a conventional particulate bridging or weightingagent, for example barite; acid-soluble materials such as calciumcarbonate; water-soluble materials such as alkali metal halides; and,other sparingly water-soluble materials such as magnesium borate andmagnesium salts of carboxylic acids. These conventional particulatebridging agents may be employed in either an oil-based wellbore fluid orin an aqueous based wellbore fluid. Where the conventional particulatebridging agent is comprised of a water-soluble or sparinglywater-soluble material, it is employed in an aqueous based fluid inamounts above the saturation concentration of the water-soluble orsparingly water-soluble material in water at the conditions encountereddownhole so as to provided suspended particles of the conventionalparticulate bridging agent. Water-based wellbore fluids may additionallycomprise particulate solid bridging agents comprised of oil-solublematerials such as resins. Suitable resins include thermoplastic resinsderived from the polymerization of hydrocarbons, having an amorphous orcrystalline structure which allows it to be crushed and ground at roomtemperature while retaining its strength so that it remainsnon-deformable when subjected to pressure in the pores and fissures of arock formation. These resins have a melting point above the temperatureencountered downhole and are insoluble in aqueous based treatment fluidsbut are soluble in produced crude oils and gas condensates. Examples ofpreferred resins include coumarone-indene resins, and alkylated aromaticresins.

Preferably, the sparingly water-soluble particulate bridging agentemployed in the present invention comprises a significant portion of thesuspended solids contained in the wellbore fluid and hence in the filtercake. Suitably, the sparingly water-soluble particulate bridging agentcomprises at least 15% by volume, preferably at least 30% by volume,more preferably at least 60% by volume of the suspended solids of thewellbore fluid (the remainder being conventional particular bridgingagents, weighting agents, drilled solids, and clays). Without wishing tobe bound by any theory it is believe that dissolution of the sparinglywater-soluble particulate bridging agent creates voids in the filtercake thereby rendering it permeable. Where the filter cake is formed ina production well, the filter cake is readily degraded when the well isput into production owing to produced fluids flowing more freely throughthe permeable filter cake. Accordingly, other solids that are depositedin the filter cake become entrained in the produced fluid such that thefilter cake is removed from the wellbore wall.

Where the wellbore fluid is an aqueous based fluid, the wellbore fluidmay comprise additional additives for improving the performance of thewellbore fluid with respect to one or more properties. Examples ofadditives that may be added to aqueous based wellbore fluids includeviscosifiers, weighting agents, density increasing water-soluble salts,fluid loss control agents (also known as filtration control additives),pH control agents, clay or shale hydration inhibitors (such aspolyalkylene glycols), bactericides, surfactants, solid and liquidlubricants, gas-hydrate inhibitors, corrosion inhibitors, defoamers,scale inhibitors, emulsified hydrophobic liquids such as oils, acidgas-scavengers (such as hydrogen sulfide scavengers), thinners (such aslignosulfonates), demulsifiers and surfactants designed to assist theclean-up of invaded fluid from producing formations.

Water-soluble polymers may be added to an aqueous based wellbore fluidto impart viscous properties, solids-dispersion and filtration controlto the fluid. A wide range of water-soluble polymers may be used for anaqueous based wellbore fluid including cellulose derivatives such ascarboxymethyl cellulose, hydroxyethylcellulose,carboxymethylhydroxyethyl cellulose, sulphoethylcellulose; starchderivatives (which may be cross-linked) including carboxymethyl starch,hydroxyethylstarch, hydroxypropyl starch; bacterial gums includingxanthan, welan, diutan, succinoglycan, scleroglucan, dextran, pullulan;plant derived gums such as guar and locust-bean gums and theirderivatives; synthetic polymers and copolymers derived from any suitablemonomers including acrylic acid or methacrylic acid and their hydroxylicesters (for example, hydroxyethylmethacrylic acid), maleic anhydride oracid, sulphonated monomers such as styrenesulphonic acid and AMPS,acrylamide and substituted acrylamides, N-vinylformamide andN-vinylacetainide, N-vinylpyrrolidone, vinyl acetate, N-vinylpyridineand other cationic vinylic monomers (for example, diallydimethylammoniumchloride, DADMAC); and any other water-soluble or water-swellablepolymers known to those skilled in the art. Generally, viscosifyingwater-soluble polymers are present in the wellbore fluid of the presentinvention in an amount sufficient to maintain the bridging and weightingsolids in suspension and provide efficient clean out from the well ofdebris such as drilled cuttings. The viscosifying polymer may be presentin the wellbore fluid in an amount in the range of 0.2 to 5 pounds ofviscosifier per barrel of wellbore fluid, preferably 0.5 to 3 pounds perbarrel of wellbore fluid.

Rheological control (for example, gelling properties) can also beprovided to the aqueous based wellbore fluid by adding clays and/orother inorganic fine particles. Examples include bentonite,montmorillonite, hectorite, attapulgite, sepiolite, Laponite™ (exLaporte) and mixed metal hydroxides.

A fluid loss control additive may be used to fill the voids between theparticulate bridging agent. Besides the water-soluble polymers listedabove, examples of fluid loss control additives for water-based wellborefluids include causticised lignite, modified lignites, cross-linkedlignosulphonates and the like. Thus, these fluid loss control additivesare dissolved macromolecules that are capable of adsorbing onto thebridging solids or are macromolecules that are in colloidal dispersionin the aqueous base fluid, for example, a hydrated polymer that adopts acoiled conformation when dispersed in the aqueous base fluid renderingthe hydrated polymer capable of plugging micro- or nano-sized pores inthe filter cake.

Suitable pH control agents for aqueous based wellbore fluids includecalcium hydroxide, magnesium hydroxide, magnesium oxide, potassiumhydroxide, sodium hydroxide and the like.

Where the wellbore fluid is an oil based fluid, the wellbore fluid maycomprise additional additives for improving the performance of the,wellbore fluid with respect to one or more properties. Examples ofadditives that may be added to oil-based wellbore fluids includeviscosifiers, surfactants (for forming stable water-in-oil emulsions andto oil-wet the surface of mineral weighting agents), fluid loss controladditives, (also known as filtration control additives), lubricants(solid and liquid), and acid gas scavengers (for example, hydrogensulfide scavengers).

A viscosifier may be added to the oil-based wellbore fluid to impartviscous properties, solids suspension and hole cleaning properties tothe fluid. Normally the viscosifier is a montmorillonite or hectoriteclay that has been treated with fatty quaternary ammonium salts torender the clay dispersible and exfoliatable in the oil-based wellborefluid. Oil-soluble polymers and oligomers may be used as rheologicalmodifiers.

Surfactants that may be added to the oil-based fluid to form stablewater-in-oil emulsions and to oil-wet the surface of mineral weightingagents include fatty acids such as Tall Oil Fatty Acid (TOFA) andcondensation products of TOFA with polyalkylene amines such astriethylenetetramine. The resulting fatty amidoamine and imidazolineproducts may be used as is or they may be further reacted with, forexample, maleic anhydride to improve their performance. Where thesurfactant contains a carboxylic acid functional group, such groups aregenerally converted to the corresponding calcium salt by addition oflime.

Suitable fluid loss control additives that may be added to the oil-basedwellbore fluid include asphalt, blown asphalt, sulphonated asphalt,gilsonite, fatty amine-modified lignite, and syntheticoil-soluble/swellable polymers.

The present invention will now be illustrated with respect to thefollowing examples

Solubility Tests

The following tests show the solubility in water and in aqueous acidicsolutions of the sparingly water-soluble materials.

EXAMPLE 1 Solubility of Melamine

The solubility of Melamine in water over a range of temperatures isgiven below in Table 1. The person skilled in the art would understandthat a sufficient quantity of water is all that is required to dissolveparticulate melamine deposited in a well, especially if the well isallowed to warm up towards its natural (prevailing) temperature afterthe cooling experienced during drilling of a wellbore or duringinjection of cold water from the surface. Accordingly, particulatemelamine may automatically clean up (dissolve) in water mat may beproduced from a well along with hydrocarbons, or in water that is pumpedinto an injection well to maintain reservoir pressure.

TABLE 1 Temperature Solubility of Melamine (° C.) (% by weight) 20 0.335 0.6 50 1.05 60 1.5 80 3.0 100 5 120 8

Melamine is also readily soluble in warm or hot acids such as aceticacid and hydrochloric acid. Thus, a mixture of melamine (25.2 g, 0.2M),250 ml of water and 24 g acetic acid (0.4M) gives a clear solution whenheated to a temperature of 80° C. Similarly a mixture of melamine (126g, 1 M) and 1985 ml of 1.0075M hydrochloric acid produces a clearsolution when heated to a temperature of 83° C.

The solubility of melamine in aqueous acidic solutions is advantageouswhere stimulation of the well by acid injection is contemplated, orwhere large amounts of particulate melamine are placed in the well, forinstance as lost circulation material plugs in fractured formations.

EXAMPLE 2 Solubility of Lithium Carbonate

The solubility of lithium carbonate in water over a range oftemperatures is given below in Table 2. As for Example 1, the personskilled in the art would understand that a sufficient quantity of wateris all that is required to dissolve lithium carbonate particles that aredeposited in a well. As before, this could be produced water or waterpumped into an injection well, or an aqueous fluid placed into the wellfor the purpose of dissolving the lithium carbonate particles. Thereduction in solubility with increasing temperature is an advantagewhere particulate lithium carbonate is used in higher temperature wells(for example wells having a bottom hole temperature (BHT) of 100° C. ormore) in that premature dissolution of the solid particles is moreeasily avoided.

TABLE 2 Solubility of Lithium Temperature Carbonate (° C.) (g per 100 gof water) 20 1.33 40 1.17 60 1.01 80 0.85 100 0.72

Lithium carbonate also rapidly dissolves in acids. For instance, aceticacid reacts with lithium carbonate to generate lithium acetate which isvery soluble in aqueous solutions while hydrochloric acid reacts withlithium carbonate to generate the highly soluble lithium chloride salt.The ability to remove particulate lithium carbonate by pumping an acidinto a well is an advantage where large amounts of particulate lithiumcarbonate are placed in the well, for instance as lost circulationmaterial plugs in fractured formations.

Lithium carbonate also shows an enhanced solubility in water in thepresence of carbon dioxide, which is frequently found in fluids producedfrom oil-wells or gas-wells (owing to the formation of lithiumbicarbonate, LiHCO₃). For instance, at a temperature of 60° C. and at apressure of 50 atmospheres of CO₂, 100 g of saturated solution contains9.61 g of LiHCO₃.

The high solubility of LiHCO₃ is particularly advantageous in gas wellssince the gas in the formation is almost inevitably saturated with watervapour and generally contains high concentrations of CO₂. As gas flowsthrough the gas-bearing formation towards a producing gas well, thepressure reduces causing adiabatic cooling and condensation of water.The condensed water together with the high concentration of CO₂ willtherefore dissolve particulate lithium carbonate residues without anyneed to pump dissolving fluids from the surface.

EXAMPLE 3 Solubility of Magnesium Sulfite

The solubility of magnesium sulfate in water over a range oftemperatures is given below in Table 3. As for Examples 1 and 2, asufficient quantity of water is all that is required to dissolveparticulate magnesium sulfite deposited in a well. Thus, the particulatemagnesium sulfite residues may automatically clean up (dissolve) in thewater that may be produced along with hydrocarbons, or in the water thatis pumped into an injection well to maintain reservoir pressure.Alternatively water or aqueous mixtures may be pumped into the well todissolve the particulate magnesium sulfite residues.

TABLE 3 Solubility of Magnesium Temperature Sulfite (° C.) (% by weight)25 0.65 42 0.94 50 0.84 85 0.62 98 0.61

Magnesium sulfite is also readily dissolved in aqueous solutions ofacids such as acetic or hydrochloric acid to produce sulphur dioxide andthe very soluble magnesium acetate or magnesium chloride respectively.Even partial acidification to magnesium bisulfite is effective indissolving particulate magnesium sulfite in that magnesium bisulfite isvery water-soluble. For example, magnesium bisulfite is availablecommercially as a 30% by weight aqueous solution from Sigma Aldrich.

Alternatively oxidising agents such as hydrogen peroxide will cause thedissolution of magnesium sulfite by converting it to the solublemagnesium sulfate (62.9 g of magnesium sulfate dissolves in 100 g ofwater at a temperature of 20° C.).

EXAMPLE 4 Solubility of Lithium Phosphate

Lithium phosphate (Li₃PO₄) has a relatively low solubility in water(0.038 g per 100 g water at a temperature of 20° C.). It is thereforeless preferred for applications where water (produced water, injectionwater, or aqueous clean-up fluid) is used to dissolve the particulateresidues.

However mild acidification with, for example, acetic acid orhydrochloric acid increases the solubility greatly. For instance,LiH₂PO₄ is very soluble in water at 55% by weight.

EXAMPLE 5 Water-Based Wellbore Fluid Formulations

The following tests relate to water-based wellbore fluid formulations.

Fluid Formulations 1-4 (see Table 4 below) are suitable for use asdrilling fluids, completion fluids such as a perforating pill or anunder-reaming fluid, or workover fluids such as a kill fluid. FluidFormulation 4 represents a typical prior art wellbore fluid that iscurrently used in the industry as, for example, a reservoir drillingfluid. This prior art fluid contains water-insoluble calcium carbonatebridging solids and is included for comparative purposes. The propertiesof Fluid Formulations 1-4 are given in Table 5 below.

Materials:

Powdered melamine, lithium carbonate, lithium phosphate and potassiumchloride were all as supplied by Aldrich UK (laboratory chemicalsupplier). DuoVis™ (xanthan gum viscosifier), DualFlo™ (starchderivative Fluid loss Reducer) and Starcarb™ (calcium carbonate powder)were supplied by M-I Swaco llc.

The Fluid Formulations were tested in accordance with ISO 10416: 2002(API RP 13I 7th edition). The Fluid Loss results are also presented inTable 5 below.

TABLE 4 Fluid Formulations Component (g) Fluid 1 Fluid 2 Fluid 3 Fluid 4Deionised water 330 330 330 330 DuoVis 1.0 1.0 1.0 1.0 DualFlo 4.0 4.04.0 4.0 Potassium Chloride 10 10 10 10 Melamine 16 — — — Lithiumcarbonate — 20 — — Lithium phosphate — — 16 — Starcarb — — — 25 Causticsoda To pH None To pH 10.0 To pH 10.0 10.0 (pH 11.0)

The varying gravimetric dose of the powders is to provide approximatelythe same loading by volume as the comparative Starcarb fluid (Fluid 4).

TABLE 5 Properties of the Fluid Formulations PROPERTIES Fluid 1 Fluid 2Fluid 3 Fluid 4 Plastic Viscosity cP 12 12 12 13 Yield Point lb/100 ft²16 17 17 17 Gels(10 sec/10 min) 6/7 7/8 7/8 8/9 API Fluid Loss 6.8 6.59.8 6.4 (mls) (determined according to ISO 10416)

After the API Fluid Loss test, the excess wellbore fluid was decantedfrom the cell employed in the test and was replaced with deionisedwater. The cell was resealed, pressurised to 100 psi with nitrogen, andthe permeation rate through the filter cake was measured for 30 minutes.

A similar test was performed by repeating the API Fluid Loss test toprovide new filter cakes from Fluids 2 and 4, followed by permeatingdeionised water that was pressurised with carbon dioxide to 100 psi.

A similar test was performed by repeating the API Fluid Loss test toprovide a filter cake with Fluids 1 to 4, followed by permeating 5%Acetic acid for 30 minutes, or until the liquid in the cell was allpassed through the filter cake.

The results of these additional tests are given in Table 6 below, whichshows average permeation rates (mls/min).

TABLE 6 Fluid Loss Test Results Fluid 2 Fluid 3 Fluid 4 Fluid 1 (lithium(lithium (calcium Permeant fluid (melamine) carbonate) phosphate)carbonate) Deionised water 7.4  0.52 0.32 0.18 Deionised water + — 1.8 —0.37 100 psi CO₂ top pressure 5% acetic acid 10.6  24.0  9.0  1.56

The rate of flow of deionised water through the lithium phosphate andlithium carbonate-containing filter cakes is clearly improved comparedto the benchmark calcium carbonate-containing filter cake (Fluid 4). Therates are still quite slow because the Duovis and DualFlo polymersconcentrated in the filter cake reduce the flow rate and hence thedissolution of the sparingly water-soluble particles during the short(30 minutes) duration of the test.

The melamine-containing filter cake rapidly developed a much higherpermeability to deionised water.

The presence of carbon dioxide increased the flow rate of water throughthe lithium carbonate containing filter cake more than three-fold.

The sparingly water-soluble solids of the present invention react to 5%acetic acid much more rapidly than particulate calcium carbonate (theindustry norm).

EXAMPLE 6 Lost-Circulation Material and Water-Based Lost-CirculationControl Fluid

A base screen was removed from an API Fluid Loss cell and a bed of aboutone inch of 20-30 mesh sand was placed in the cell. This sand bedrepresents an extremely high permeability rock formation. Water was thenpoured through the bed to water-wet the sand.

A simple drilling fluid was mixed according to the followingformulation:

Deionised water 330 g  Duovis ™ 1.5 g DualFlo ™ 3.5 g Barite  63 g

A portion of this drilling fluid was gently poured on top of the sandbed. On pressurising the cell to a pressure of 50 psi, the completedrilling fluid immediately flowed through the sand bed in less than 3seconds. This represents a lost circulation problem such as may beencountered in the field.

A slurry was obtained by mixing 100 g of melamine (ex Aldrich) in 290 gof water, and 100 mls of the slurry was poured into the cell. Onpressurising to 50 psi the aqueous phase of the slurry immediatelyfiltered through the sand bed. On opening the cell a white filter cakelayer of melamine particles was observed on top of the sand bed. Aportion of the “simple” drilling fluid was poured into the cell whichwas re-pressurised to 50 psi. A much slower stream of drilling fluidpassed through the sand bed, but all (about 100 mls) was still lost fromthe cell over a period of about 30 seconds. On opening the cell it wasobserved that the drilling fluid had all flowed through a smalldiscontinuity in the bed of melamine particles.

Melamine particles were then added to the remaining drilling fluid at adose of approximately 12.5 lbs/bbl. On placing this fluid into the celland re-pressurising to 50 psi, the drilling fluid started to flowthrough the sand pack but slowed to a virtual stop in about 5-10seconds. The pressure was increased to 100 psi. The effluent rate fromthe cell was then stabilised at a normal, slow filtration rate.

This Experiment illustrates the use of sparingly water-soluble solidparticles as Lost Circulation Material, either in a specially designedfluid pumped into place in a wellbore to control fluid losses, or as anadditive to a wellbore fluid such as a drilling fluid. The addition ofthe sparingly water-soluble material to drilling fluids may used be tostop fluid losses, but it may also be used pre-emptively to avoid theoccurrence of such losses.

The particle size of the melamine obtained from Aldrich was measured bydry screening using a vibratory screen shaker. Results in weight percentare as follows:

>500 microns 0.22% <500 > 300 microns 1.60% <300 > 150 microns 74.0%<150 microns 24.2%

Such sized particles are well-suited to bridging the pores in extremepermeability sand formations, and also for accumulating in fractures ofwidth less than about 1 mm by rapid filtration of a high-solids slurryof the particles which is flowing into the fracture.

EXAMPLE 7 Oil-Based Drilling Fluid Containing Melamine Particles, andTreatment of the Filter Cake Therefrom to Establish the Flow-Through ofSeawater

An oil-based drilling fluid was prepared, based upon the FazePro™product of M-I Swaco LLC (see Table 7 below). The invert emulsion ofthis oil-based drilling fluid is designed to de-stabilise upon theapplication of an acid thereby enabling improved clean-up compared toconventional oil-based drilling fluids. The addition of melamine powderprovides bridging and filter cake material to seal the sand-face ofpermeable formations. After drilling, the filter cake may be treatedwith an acid solution to disrupt the emulsion within the filter cake inorder to increase the cake permeability. The acid also starts todissolve some of the particulate melamine. In the case of a seawaterinjection well, the acid can be followed by injection of seawater whichcontinues to dissolve the remaining melamine until the residues arecompletely removed.

This Example shows that an oil-based drilling fluid with suitableproperties for drilling purposes can be formulated with melaminebridging solids. Subsequently the filter cake is treated with an acidsolution followed by the flow of injected seawater, both of which fluidsare active in removing the seal that was provided by the filter cake.

The oil-based drilling formulation was mixed using a Silverson L4RTMixer fitted with a high shear head. The mixing times per component areshown in Table 7 below. The mixer speed was at about 6000 RPM. Thetemperature was monitored throughout and maintained at 150° F. or lessby the use of a cooling water bath.

TABLE 7 Concentration Product (ppb) Order Time DF-1 BASE OIL ™ (a) 134.5 1= FAZEMUL ™ (b) 12.0  1=  5 mins FAZEWET ™ (b) 6.0  1= TRUVIS ™ (b)1.0 4  2 mins Lime 4.0 5  2 mins ECOTROL RD ™(b) 0.5 6 16 mins 1.35 ppgCaBr2 Brine 164.9 7 20 mins Melamine powder 30 8 15 mins (a) exTotalFinaElf UK Limited (b) ex Trademark M-I Swaco llc

After mixing, the oil-based drilling fluid was hot rolled at atemperature of 150° F. for 16 hours to simulate heating downhole in thefield. The viscous properties and the High Temperature/High PressureFluid Loss (HTHP FL) were then measured and are given in Table 8 below.

TABLE 8 Rheological Properties at 120° F./48.8° C. Plastic Viscosity(cP) 15 Yield Point (lb/100 ft²) 14 10 sec gel (lb/100 ft²) 7 10 min gel(lb/100 ft²) 7 HTHP Fluid Loss (mls) 3.1 At 200° F. and 500 psiThe results presented in Table 8 show that satisfactory rheological andfiltration performance was obtained.

After the HTHP Fluid loss test the excess drilling fluid was drainedfrom the cell and replaced by a solution of 5% glacial acetic acid inkerosene. The cell was closed and heated to a temperature of 45° C. Theacid solution was then pressurised to 100 psi so that the solutionpermeated through the filter cake, the flow-through weight beingmeasured vs. time, as recorded below in Table 9.

TABLE 9 Permeation of Acid Solution through Filter cake Time Permeatedacid solution (minutes) (grams)  1 7.604  5 15.878 10 25.14 15 39.548 15minutes 45 seconds Gas breakthrough

The cell was then refilled with seawater and heated to a temperature of45° C. On pressurising to 100 psi, the seawater rapidly passed throughthe filter cake (66.5 g in 17 seconds). Examination of the filter cakeshowed that irregular areas had been etched away leaving some whitemelamine residues. The filter cake residues on the filter paper wereplaced in 500 mls of seawater and held at a temperature of 45° C. for 72hours. After this time no visible melamine particles remained.

This is very advantageous for seawater injection wells where seawaterinjection is usually continued for years, leaving little chance that anyresidual melamine filter cake remains undissolved. Thus the injectivityof the seawater is maximised.

1-27. (canceled)
 28. A method of forming a filter cake on the walls of awater injection wellbore or a production wellbore that penetrates aporous and permeable rock formation and of subsequently removing thefilter cake from the walls of the wellbore comprising the steps of: (a)placing a wellbore fluid in the wellbore wherein the wellbore fluidcomprises a base fluid and a particulate bridging agent comprised of asparingly water-soluble material selected from the group consisting oflithium carbonate, lithium phosphate (Li₃PO₄), and magnesium sulfite;(b) permitting the particulate bridging agent to deposit from thewellbore fluid onto and/or into the walls of the wellbore therebyforming the filter cake, whereby fluid loss to the formation through thefilter cake is reduced; and (c) removing the filter cake from the wallsof the wellbore by injecting water that is undersaturated with respectof the bridging agent from the injection wellbore into the formation orproducing fluid comprising hydrocarbon and co-produced water from theformation into the production wellbore wherein the co-produced water isundersaturated with respect to the bridging agent.
 29. A method asclaimed in claim 28 wherein the sparingly soluble bridging agent ispresent in the wellbore fluid in an amount in the range of 1 to 70% byweight, preferably, 2 to 70% by weight, for example, 2 to 50% by weight.30. A method as claimed in claim 28 wherein a fluid loss controladditive is included in the wellbore fluid.
 31. A method as claimed inclaim 28 wherein the base fluid is water or an aqueous solution of adensity increasing water-soluble salt.
 32. A method of forming a filtercake on the walls of a wellbore that penetrates a porous and permeablerock formation and of subsequently removing the filter cake from thewalls of the wellbore comprising the steps of: (a) placing a wellborefluid in the wellbore wherein the wellbore fluid comprises a base fluidand a particulate bridging agent comprised of a sparingly water-solublematerial selected from the group consisting of lithium carbonate,lithium phosphate (Li₃PO₄), and magnesium sulfite; (b) permitting theparticulate bridging agent to deposit from the wellbore fluid onto thewalls of the wellbore thereby forming the filter cake, whereby fluidloss to the formation through the filter cake is reduced; and (c)removing the filter cake from the walls of the wellbore by (i) placing aclean-up fluid downhole wherein the clean-up fluid is undersaturatedwith respect to the bridging agent or is an aqueous solution of an acidor a precursor of a weak acid; and (ii) leaving the cleanup fluid tosoak across the interval of the wellbore where it is desired to removethe filter cake for a sufficient period of time to either dissolve thebridging agent or to solubilise the bridging agent to the extent thatthe particles are sufficiently reduced in size to permit their removalfrom the filter cake.
 33. A method as claimed in claim 32 wherein theparticles are sufficiently reduced in size to permit the removal of theremaining filter cake with a wash fluid or by subsequently producingwater from the formation or injecting water into the formation.
 34. Amethod as claimed in claim 32 wherein the sparingly soluble bridgingagent is present in the wellbore fluid in an amount in the range of 1 to70% by weight, preferably, 2 to 70% by weight, for example, 2 to 50% byweight.
 35. A method as claimed in claim 32 wherein a fluid loss controladditive is included in the wellbore fluid.
 36. A method as claimed inclaim 32 wherein the base fluid is water or an aqueous solution of adensity increasing water-soluble salt.
 37. A method as claimed in claim32 wherein the sparingly water-soluble particulate bridging agent iscomprised of magnesium sulfite, and the clean-up fluid comprises anaqueous solution of an oxidizing agent that is capable of convertingmagnesium sulfite to water-soluble magnesium sulfate wherein theoxidizing agent is present in the clean-up fluid in an amount of 1 to20% by weight.
 38. A method as claimed in claim 37 wherein the oxidizingagent is selected from the group consisting of hydrogen peroxide,persulfate salts, and per-acids.
 39. A method of drilling a wellborethrough a porous and permeable rock formation using a drilling fluidcomprising a base fluid, a fluid loss control additive, and aparticulate bridging agent comprised of a sparingly water-solublematerial selected from the group consisting of lithium carbonate,lithium, phosphate (Li₃PO₄), and magnesium sulfite wherein the pressureof the drilling fluid in the wellbore is maintained at above thepressure in the porous and permeable rock formation such that a filtercake deposits on the walls of the wellbore and reduces fluid loss fromthe drilling fluid to the rock formation.
 40. A drilling method asclaimed in claim 39 wherein the sparingly soluble bridging agent ispresent in the wellbore fluid in an amount in the range of 1 to 70% byweight, preferably, 2 to 70% by weight, for example 2 to 50% by weight.41. A drilling method as claimed in claim 39 wherein the sparinglywater-soluble particulate bridging agent of the drilling fluid has aparticle size distribution in the range of from about 0.1 micron to 600microns.
 42. A drilling method as claimed in claim 39 wherein the basefluid of the drilling fluid is water or an aqueous solution of a densityincreasing water-soluble salt.
 43. A wellbore fluid comprising a basefluid and a particulate bridging agent comprised of a sparinglywater-soluble material selected from the group consisting of lithiumcarbonate, lithium phosphate (Li₃PO₄), and magnesium sulfite wherein theparticulate bridging agent is present in the wellbore fluid in an amountin the range of 1 to 70% by weight, preferably, 2 to 50% by weight. 44.A wellbore fluid as claimed in claim 43 wherein the base fluid ispresent in the wellbore fluid in an amount in the range of from about 30to 99% by weight of the fluid.
 45. A wellbore fluid as claimed in claim43 wherein the wellbore fluid is a drilling, servicing or completionfluid and the sparingly water-soluble particulate bridging agent has aparticle size distribution in the range of from about 0.1 micron to 600microns.
 46. A wellbore fluid as claimed in claim 43 wherein thewellbore fluid is a lost circulation fluid and the sparinglywater-soluble particulate bridging agent is present in the lostcirculation fluid in an amount of from 10 to 60% by weight and has aparticle size distribution in the range of from about 50 microns to 10mm.
 47. A wellbore fluid as claimed in claim 43 wherein the wellborefluid is an aqueous based fluid and the wellbore fluid comprises atleast one additional additive selected from the group consisting ofviscosifiers, weighting agents, density increasing water-soluble salts,filtration or fluid loss control agents, pH control agents, clay orshale hydration inhibitors, bactericides, surfactants, solid and liquidlubricants, gas-hydrate inhibitors, corrosion inhibitors, defoamers,scale inhibitors, emulsified hydrophobic liquids such as oils, acidgas-scavengers (such as hydrogen sulfide scavengers), thinners (such aslignosulfonates), and demulsifiers.
 48. A wellbore fluid as claimed inclaim 47 wherein the aqueous based wellbore fluid comprises a fluid losscontrol agent selected from the group consisting of water-solublepolymers, lignites, modified lignites, and cross-linkedlignosulphonates.
 49. A wellbore fluid as claimed in claim 43 whereinthe wellbore fluid is an oil based fluid comprising at least oneadditional additive selected from the group consisting of viscosifiers,surfactants (for forming stable water-in-oil emulsions and to oil-wetthe surface of mineral weighting agents), fluid loss control additives,lubricants (solid and liquid), and acid gas scavengers (for example,hydrogen sulfide scavengers).